WO2023172823A2 - Renforcement de pointes de fracture pour la fracturation de précision - Google Patents

Renforcement de pointes de fracture pour la fracturation de précision Download PDF

Info

Publication number
WO2023172823A2
WO2023172823A2 PCT/US2023/063236 US2023063236W WO2023172823A2 WO 2023172823 A2 WO2023172823 A2 WO 2023172823A2 US 2023063236 W US2023063236 W US 2023063236W WO 2023172823 A2 WO2023172823 A2 WO 2023172823A2
Authority
WO
WIPO (PCT)
Prior art keywords
fracture
tip
fluid
reservoir
solid
Prior art date
Application number
PCT/US2023/063236
Other languages
English (en)
Other versions
WO2023172823A3 (fr
Inventor
Vibhas Pandey
Original Assignee
Conocophilips Company
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Conocophilips Company filed Critical Conocophilips Company
Publication of WO2023172823A2 publication Critical patent/WO2023172823A2/fr
Publication of WO2023172823A3 publication Critical patent/WO2023172823A3/fr

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V20/00—Geomodelling in general
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/20—Computer models or simulations, e.g. for reservoirs under production, drill bits

Definitions

  • the disclosure generally relates to methods, devices and systems for fracturing hydrocarbon formations to improve the production of hydrocarbons.
  • fracture tips are strengthened with solid deposits in the tips where needed to control fracture propagation.
  • Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking.
  • the resistance to flow in the formation increases and the pressure in the wellbore increases to a value called the break-down pressure, that is the sum of the in situ compressive stress and the strength of the formation.
  • the productivity index defines the rate at which oil or gas can be produced at a given pressure differential between the reservoir and the wellbore
  • the injectivity index refers to the rate at which fluid can be injected into a well at a given pressure differential.
  • a fluid not containing any solid (called the “pad”) is injected first, until the fracture is wide enough to accept a propping agent.
  • the pad fluid plus propping agent are injected next.
  • the purpose of the propping agent is to keep the fracture open once the pumping operation ceases.
  • man-made ceramic beads are used to hold open or “prop” the fracture (see e.g., FIG. 1).
  • sand is normally used as the propping agent.
  • the fractures can be acid etched instead of being propped open. Usually, this is followed by a final flush, but there are many variations on these basic techniques.
  • Fractures may occur in different directions, have different lengths and widths and may intersect or branch, providing a complex pattern of fractures.
  • “Hydraulic fracture geometry” refers to the length, direction and overall pattern of fractures. Longitudinal fractures, for example, generally travel along the well axis and typically have excellent connectivity with the well, but don't reach very far into the reservoir. Transverse fracturing has the potential to reach further into the reservoir since fracture direction is perpendicular to the wellbore, and many transverse fractures are bi-winged fractures proceeding in opposite directions from the initiation point.
  • the resulting geometry from a fracking job is a complex function of initial reservoir stress conditions (global and local), reservoir rock properties such as heterogeneous and anisotropic rock mechanical properties (Young’s modulus and Poisson’s ratio), permeability, porosity, the preexisting natural fracture system, and operational conditions such as injection rate, volume, and pressure.
  • problems include poor vertical height of fractures, which tend to be limited because the fractures do not like to grow through the highly laminated sequences typical of shale. Further, there is also evidence of fracture collapse. Evaluation of 200 field trials with different frac designs and 143 trials in which restimulation treatments were documented indicated that fractures frequently fail to provide durable, highly conductive pathways for hydrocarbons to flow.
  • transverse fractures Another challenge with transverse fractures is the extremely limited intersection area between the well bore and the fracture. As shown in FIG. 2, a longitudinal fracture that grows along the axis of the well bore can provide a very large intersection between the well and fracture. However, the transverse fracture has very limited contact with the wellbore. This tends to cause choking near the wellbore, as all the fluid has to reach the wellbore through an increasingly constrained space.
  • a 5,000-foot open-hole lateral drilled in the direction of the maximum horizontal stress may achieve 10,000 linear feet of intersection with a longitudinal fracture.
  • the well bore circumference provides merely 1.6 feet of linear intersection.
  • oil must travel 6,250 times faster in the transverse fracture because of converging flow geometry.
  • transverse fractures suffer from an extremely small area of intersection between the well bore and fracture, they are more vulnerable to damage related to inadequate proppant quality, low proppant concentration, overflushing, or proppant flow back.
  • transverse fracturing is very promising and already providing many successful reservoir developments, there is a need to further develop hydraulic fracture methodology.
  • great strides have been made in controlling fracture geometry, there is considerable room for improvement and this invention provides one or more of such improvements.
  • Fracture length is often referred to as half-length for bi-winged transverse fracture.
  • the half-length of a hydraulic fracture is critical to well performance for most low to medium permeability reservoirs and is generally understood and modeled as an artifact of material balance between the fracture fluid injected to create a fracture and the amount of fluid lost to the surrounding rock mass or formation.
  • the fractures are more prone to growing vertically (and extending laterally to some extent) from the point of injection, until strong barriers such as those imposed by in situ stresses are encountered in vertical direction that act to contain fracture growth.
  • the fracture half-length will increase if (a) leakoff of the fracturing fluid into the formation is controlled, and (b) if vertical growth of fracture stops or becomes near stationary once reaching such barriers.
  • the proposed innovation is aimed at strengthening the fracture tips by packing the tip with solid, non-dissolving particulate matter that functions to arrest fracture vertical growth by forming a pack along the edge of the blade-like fracture tip.
  • the upper, lower, or both of edges of the hydraulic fracture can be strengthened by this procedure.
  • a preliminary fracture is initiated at a low rate with a first low viscosity fluid.
  • solids of varying sizes are introduced into the fracture fluid at low concentrations, locking fracture geometry into place by deliberately packing the particles into the tip of the fracture. The placement and growth of the fracture largely depends on formation stress distribution across the depth and the propagation is affected by fracture toughness.
  • the fracture toughness acts like a clamp, thus offering a resistance to propagation since the fluid lag region may have pressures similar to that of vapor pressure and cannot counter the process zone stresses. If, for such a slow advancing fracture, particulate matter is forced into the edges of the fracture in the near tip region, so as to form a tightly packed porous plug, movement of the fracture tip will be impeded since additional tip pressure will be required to push the pack away before additional rock can be wetted. Thus, the edge of the fracture is now temporarily strengthened, and the fracture contained.
  • the well may be an existing well or a well completed specifically for this fracturing method. Horizontal wells are preferred, especially in shale plays, but vertical wells are sometimes used, as well as combinations of wells. Drilling multiple horizontal wells from a single pad has increasingly become a common approach for developing shale reservoirs due to significant cost, time, and environmental savings. Open hole or cased wells can be subjected to transverse fracking.
  • a fracture is initiated at a low pumping rate using a low viscosity fluid that maybe a linear gel or even brine water with solids suspension properties, and fracture geometry and growth rate are determined as taught herein or using any suitable method in the art.
  • a fracture geometry is determined to be problematic, such that tip strengthening is warranted to avoid unwanted fracture propagation, a small amount of tip strengthening material is pumped in to settle at fracture tips, the placement being controlled by the buoyancy or specific density of the solid used — buoyant solids packing upwardly growing tips, and sinking solids packing downwardly growing tips.
  • Tip strengthening is confirmed by monitoring pressure, wherein the slope of a loglog plot of pressure (x axis) versus time (y axis) is positive. A zero or negative slope indicates the need to slow the rate of pumping.
  • the tip strengthening step can optionally be repeated with a larger solid or higher concentration, further consolidating the tip.
  • the light and heavy solids can be combined in one step, and in another embodiment, the heavier solid may be combined with the main treatment plan.
  • reservoir and fracture parameters will be entered into a reservoir model, so that fracture geometry can be predicted in advance of field use.
  • the fracture plan can thus be optimized by iterated simulations, and the optimized plan implemented in a real reservoir and increased hydrocarbon produced.
  • a “tip strengthening material” can be any solid, non-dissolving material that deposits in the tip, preventing further propagation of that fracture.
  • Such materials include proppant, ceramics, bauxite, crushed shells, chemicals that solidify when exposed to temperatures, and the like.
  • a “main treatment” injection comprises the usual techniques of hydraulic fracturing, typically including a pad injection, a proppant injection and a flush, but these may be varied as needed.
  • Perforation cluster spacing and stage spacing are also important. Ideally, cluster spacing is on the order of 50-100 feet, and stage spacing is 250 to 500 feet, although some have reported better production with shorter spacings of 150 feet with a gross perforated interval of 100 ft (top perf to bottom perf) with 31 -ft perforation clusters, each spaced 50 ft apart.
  • 3-5 perforation clusters per stage there are 2-8 or 3-5 perforation clusters per stage, with 4-12 or 6-10 shots per foot, typically arranged in a spiral around the well bore with e.g., 60 degree spacing so that 1-2 foot of the bore is perforated in a cluster. Another option is to shoot 0-180° or in transverse planes.
  • 3-5 stages are fractured (e.g., 3-5 zones). These ranges are exemplary only, and other spacings and numbers may be used depending on the reservoir characteristics.
  • the fracturing method can be any suitable method or combinations of methods, provided that multiple transverse fractures are the final result.
  • the method could employ aspects of hydraulic fracking, thermal fracking, cryogenic fracking, electric fracking, explosive fracking, pneumatic fracking and the like, although hydraulic fracking, possibly combined with cryogenic fracking may be preferred, e.g., with liquid N2, LNG, liquid CO2, cold methanol, and the like.
  • preflush may be used to clean the rock and/or increase wettability.
  • Afterflush may be used to clear out gels and other polymers. The person of ordinary skill in the art knows how to include such steps in a fracking plan, and these details are not discussed extensively herein.
  • Any suitable fracturing fluid can be used, although water-based frack fluids are probably preferred, possibly with polymers to increase viscosity for proppant mobility.
  • a number of fluids are described in Table 1 :
  • a variety of proppants can be used in the method. Proppants are small crushresistant particles that are carried into the fractures by the hydraulic fracturing fluid. When the pumps are turned off and the fractures collapse these crush-resistant particles hold the fracture open, creating pore space through which natural gas can travel to the well.
  • Frac sand is the proppant most commonly used today, but aluminum beads, ceramic beads, sintered bauxite, crushed shells, and other materials have also been used. Over one million pounds of proppants can be used while fracturing a single well. Proppant use can also be reduced in carbonate/dolomite plays where acid etching is used.
  • the tip strengthening material is essentially the same material that is used as a proppant, but its use differs in that smaller grain (e.g. 100 US Mesh or 40/70 US Mesh) and heavier material are used for downward propagating loss, with smaller grains and less dense materials used for upward propagating loss.
  • smaller grain e.g. 100 US Mesh or 40/70 US Mesh
  • heavier material are used for downward propagating loss, with smaller grains and less dense materials used for upward propagating loss.
  • Corrosion inhibitors, demulsifiers, surface tension reducing agents, chemical retarding agents, clay stabilizers, friction reducers and other additives referred to above may be incorporated in the fracturing fluid if desired. Care should again be taken that the additives selected are compatible with the other components, as well as with the carrier fluid. Some commonly used additives are described below:
  • Surfactants are used to reduce surface and interfacial tension, to prevent emulsions, to water wet the formation, and to safeguard against other associated problems. Swabbing and clean-up time can be reduced by lowering surface tension.
  • Suspending Agents Agents to suspend fines. Suspension should be differentiated from dispersion. Dispersed particles usually settle in a short time. Care should be taken that suspending agents do not interfere with the tip strengthening material, but usually the tip strengthening material will be too large to be affected. [0047] Sequestering Agents: Sequestering agents act to complex ions of iron and other metallic salts to inhibit precipitation of iron. Sequestering agents are typically used if rusty tubing or casing is to be contacted.
  • Anti-Sludge Agents Some crudes, particularly heavy asphaltic crudes, from an insoluble sludge when contacted with acid.
  • the primary ingredients of a sludge are usually asphaltenes, but sludges may also contain resins and paraffin waxes, high-molecular weight hydrocarbons, and formation fines or clays. Addition of certain surfactants can prevent sludge formation by keeping colloidal material dispersed.
  • Corrosion Inhibitors temporarily slow down the reaction of acid on metal. Corrosion inhibition time varies with temperature, acid concentration, type of steel, and inhibitor concentration. Both organic and inorganic corrosion inhibitors have application in acidizing. Some organic inhibitors are effective up to the 300° F range. Extenders have been developed to increase the effective range to 400° F. Inorganic arsenic inhibitor can be used up to at least 450° F.
  • Alcohol Normally methyl or isopropyl alcohol in concentrations of 5% to 30% by volume can be used to lower surface tension.
  • the use of alcohol in acid will accelerate the rate of well clean-up and improve clean-up, particularly in dry gas wells. Disadvantages are increased inhibitor problems and possible salt precipitation.
  • Fluid Loss Control Agents may be required to reduce leak-off, particularly in fracture acidizing. The preferred method of selecting fluid loss control agents is to run fluid loss tests on cores from the formation to be fracked.
  • Diverting or Bridging Agents Fluids will usually follow the path of least resistance, usually the lesser damaged intervals, unless diverting or bridging agents are employed to allow relatively uniform treatment of various porous zones open to the wellbore. Diverting or bridging agents are distinct from the tip strengthening materials in their usage, such that diverting or bridging agents are gels that solidify to form impervious barriers. These barriers are set in the flow path by first pumping the gelling components into the reservoir, providing an activator or other condition required for setting, and allowing the agent to set in the flow path. [0053] The invention includes the following one or more embodiments, in any combination thereof: Any method herein described wherein solid settling is simulated in said model reservoir.
  • a “fracture” is a crack, delamination, surface breakage, separation or other destruction within a geologic formation or fraction of formation not related to foliation or cleavage in metamorphic formation, along which there has been displacement or movement relative to an adjacent portion of the formation.
  • a fracture along which there has been lateral displacement may be termed a fault.
  • the fracture When walls of a fracture have moved only normal to each other, the fracture may be termed a joint. Fractures may enhance permeability of rocks greatly by connecting pores together, and for that reason, joints and faults may be induced mechanically in some reservoirs in order to increase fluid flow. Fractures may also be natural.
  • a “transverse fracture” is a fracture that is more than 15 degrees deviated from the axis of the wellbore and is usually roughly perpendicular thereto.
  • a “longitudinal” or “axial” fracture is oriented 15 degrees or less from the axis of the wellbore, e.g., substantially parallel to the wellbore.
  • a “hydraulic fracture” is a fracture at least partially propagated into a formation, wherein the fracture is created through injection of pressurized fluids into the formation. While the term “hydraulic fracture” is used, the techniques described herein are not limited to use in hydraulic fractures. The techniques may be suitable for use in any fractures created in any manner considered suitable by one skilled in the art. Hydraulic fractures may be substantially horizontal in orientation, substantially vertical in orientation, or oriented along any other plane. Generally, the fractures tend to be vertical at greater depths, due to the increased mass of the overburden.
  • hydraulic fracturing is a process used to create fractures that extend from the wellbore into formations to stimulate the potential for production.
  • a fracturing fluid typically viscous, is generally injected into the formation with sufficient pressure, for example, at a pressure greater than the lithostatic pressure of the formation, to create and extend a fracture.
  • a proppant may often be used to “prop” or hold open the created fracture after the hydraulic pressure used to generate the fracture has been released.
  • Parameters that may be useful for controlling the fracturing process include the pressure of the hydraulic fluid, the viscosity of the hydraulic fluid, the mass flow rate of the hydraulic fluid, the amount of proppant, and the like.
  • Overburden refers to the subsurface formation overlying the formation containing one or more hydrocarbon-bearing zones (the reservoirs).
  • overburden may include rock, shale, mudstone, or wet/tight carbonate (such as an impermeable carbonate without hydrocarbons).
  • An overburden may include a hydrocarbon-containing layer that is relatively impermeable. In some cases, the overburden may be permeable.
  • Overburden stress refers to the load per unit area or stress overlying an area or point of interest in the subsurface from the weight of the overlying sediments and fluids.
  • the “overburden stress” is the load per unit area or stress overlying the hydrocarbon-bearing zone that is being conditioned or produced according to the embodiments described.
  • the magnitude of the overburden stress may primarily depend on two factors: 1) the composition of the overlying sediments and fluids, and 2) the depth of the subsurface area or formation.
  • underburden refers to the subsurface formation underneath the formation containing one or more hydrocarbon-bearing zones (reservoirs).
  • the term “relatively permeable” is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy).
  • the term “relatively low permeability” is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy.
  • An impermeable layer generally has a permeability of less than about 0.1 millidarcy.
  • shale may be considered impermeable, for example, ranging from about 0.1 millidarcy (100 microdarcy) to as low as 0.00001 millidarcy (10 nanodarcy).
  • Portion is defined as the ratio of the volume of pore space to the total bulk volume of the material expressed in percent. Although there often is an apparent close relationship between porosity and permeability, because a highly porous formation may be highly permeable, there is no real relationship between the two — a formation with a high percentage of porosity may be very impermeable because of a lack of communication between the individual pores, capillary size of the pore space or the morphology of structures constituting the pore space.
  • the diatomite in one exemplary formation type — Belridge — has very high porosity, at about 60%, but the permeability is very low, for example, less than about 0.1 millidarcy.
  • shale is a fine-grained clastic sedimentary formation with a mean grain size of less than 0.0625 mm.
  • Shale typically includes laminated and fissile siltstones and claystones. These materials may be formed from clays, quartz, and other minerals that are found in finegrained rocks. Non-limiting examples of shales include Barnett, Fayetteville, and Woodford in North America. Shale has low matrix permeability, so production in commercial quantities requires fracking to provide permeability.
  • Shale reservoirs may be hydraulically fractured as described herein to create extensive artificial fracture networks around wellbores. Horizontal drilling is often used with shale wells.
  • Stimulated reservoir volume or “SRV” is used to describe the shape and size of a fracture network created by hydraulic or other induced fracturing in low-permeability reservoirs.
  • a “step rate test” or “SRT” is where an injection fluid is injected for a defined period in a series of increasing pump rates. The resulting data are used to identify key treatment parameters of the fracturing operation, such as the pressure and flow rates required to successfully complete the treatment.
  • the SRT can be performed by the methods described at rrc.texas.gov/oil-and-gas/publications-and- notices/manuals/inj ection-disposal -well-manual/summary-of-standards-and- procedures/technical-review/step-rate-test-guidelines/ or epa.gov/sites/default/files/documents/TNFO-StepRateTest.pdf, although different jurisdictions may require different variations of these tests.
  • a “dedicated calibration injection test” is a constant rate injection test with actual fracturing fluid and is oft performed by a service company or others who own injection pumps and are able to record the injection rate and pressure data.
  • a “pressure fall-off test” is the measurement and analysis of pressure data taken after an injection well is shut in.
  • the falloff period is a replay of the injection preceding it. Consequently, it is impacted by the magnitude, length, and rate fluctuations of the injection period and any fractures.
  • Falloff testing analysis provides transmissibility, skin factor, and well flowing and static pressures.
  • An EPA test for region 6 is provided at epa.gov/sites/default/files/2015-07/documents/guideline.pdf. As above, different jurisdictions may require different variations of this test.
  • a “production well” or “producer” is completed for production, and an “injection well” or “injector” completed for injection. It is possible to convert from one type of completion to the other. For example, the lower injector well is converted to production once the wells in a SAGD wellpair are in fluid communication, but during start-up, both wells are completed for injection and steam is injected into both.
  • FIG. 1 (prior art) Hydraulic fracturing of a reservoir. Allows more gas or oil to reach the well for production.
  • FIG. 2 (prior art) Well bore contact with various fracture types. Longitudinal open-hole (top), longitudinal cemented (center), and transverse fractures (bottom).
  • FTG. 3A-B Fracture distance versus net pressure mapping. Graphs prepared using a simulator and a model that comprises a coal bed methane reservoir of permeability of 0.12 md, expected fracture conductivity of nearly 1,750 md-ft, pay zone between 3,325 and 3,375 ft (1,014.7 and 1,029.0 m) and high mobile water saturation zone below 3,425 ft (1,044 m).
  • FIG. 3A is net pressure in psi on the x axis versus distance in feet from the fracture initiation point (0) on the y axis.
  • the circle (top line) and squares (bottom line) indicating the upper and lower tips of the fracture, respectively.
  • the middle of the fracture is shown by triangles (middle line).
  • FIG. 3B is stress distribution of the formation as a function of depth. Stresses are indicated by the circles with a range of psi shown, and the star indicates a perforation cluster. In FIG. 3A, the star denotes the distance of the high stress member from the center of the perforation and aligns with the depth position in FIG. 3B.
  • the payzone and high water saturation region are highlighted by top and bottom boxes, respectively.
  • FIG. 4A-B Simulation shows possible downward growth of fracture into unwanted zones.
  • FIG. 4A is stress in psi versus true vertical depth (“TVD”) in meters with the black line indicating formation stresses in psi and the colors showing various layer types. These are yellow, red, purple and gray for clean-sandstone, dirty-sandstone, siltstone and shale respectively.
  • FIG. 4B is fracture penetration in meters versus TVD wherein the colors represent proppant coverage in lb/ft2. The high water saturation zone is shown by the blue box.
  • FIG. 5A-B Simulation depicting proppant settling at the bottom of the fracture.
  • FIG. 5A is the modeled stress distribution of the various layers in the formation and
  • FIG. 5B is fracture half-length showing proppant coverage.
  • the simulation shows higher concentrations of proppant depicted by blue color and equivalent to nearly 0.2 lbm/ft 2 based on the scale on right Y-axis, at the bottom tip of the fracture.
  • the arrows inside the fracture show the direction and magnitude of fluid velocity vector that can be scaled based on scale of “0.419 m/s” shown at the bottom of the proppant coverage scale.
  • the fracture half-length is limited to 100 m.
  • FIG. 6A-B Simulation depicting proppant settling at the bottom of the fracture.
  • FIG. 6A is the modeled stress distribution of the various layers in the formation and
  • FIG. 6B is fracture half-length showing proppant coverage. This plot shows that after strengthening the bottom tip of the fracture, the fracture can now be extended to the desired fracture half-length, and it will not grow into the high water saturation layers below thus helping to meet the objective of the fracture simulation treatment.
  • the gridded numerical model was run in a fully 3 -dimensional mode and took into account a 2-dimensional fluid flow inside the fracture, which accounts for proppant settling mechanism while also accounting for leakoff of fluid into the formation, which is a critical input in calculation of fracture geometry.
  • Simulations were performed with a fluid of small viscosity of up to 12 cP and injection rates of nearly 8 bbl/min.
  • FIG. 3A confirms that if the net pressure during the treatment (defined as fracture pressure minus in situ stress) exceeds 350 psi, the bottom stress barrier at this depth is liable to give in. As a result, the fracture can migrate downwards, as shown by the location bottom tip of the fracture in FIG. 3A.
  • the points in 3A denote the expected top, middle and bottom tips of the fracture. As can be seen, initially the top and bottom of the fractures remained confined to a total height of a mere few feet if the net pressures are limited to 225 psi.
  • the fracture appears to grow in downward direction, nearly 60 ft below the initiation point and with further increases in net pressure, tends to grow vertically in both the directions, as shown by upper and lower tip location.
  • the depth and distances are both highlighted by a star and the payzone and the high water saturation region, are highlighted by top and bottom boxes, respectively.
  • FIG. 4A shows typical output from a fracture simulator where one of the 2 equally sized fracture wings (bi-wing fracture) is illustrated with for a given fracture property along the vertical height and half-length of the fracture.
  • the track on the left shows stress distribution in the formation as a function of depth, and the various colors represent various layer lithological types described above.
  • the right portion of the plot shows the extent of fracture extension and height growth, with the various colors depicting the contour of proppant coverage inside the fracture with the units of lbm/ft 2 .
  • the small arrow shows the velocity vectors associated with fluid movements inside the fracture. The vectors can be scaled from the scale shown on the bottom of the right legend. The same implies for FIG. 4B.
  • a crosslinked frac fluid of 20 Ibm/Mgal concentration was used in the simulation and the injection rates were limited to 12.0 bbl/min to ensure that net pressures were under control and excessive height growth avoided.
  • the total proppant designed was 145,000 Ibm reaching up to a maximum concentration of 8.0 Ibm/gal to generate the desired conductivity.
  • the simulation confirms that a downward fracture growth is possible, despite our viscosity and rate precautions, since the bottom barrier is not sufficiently strong to contain the fracture.
  • the downward fracture growth results in the fracture contacting non-pay rock and considerable placement of proppant in regions that will not contribute to production. Also, the penetration of the fracture in rocks with high mobile-water saturation below 1,044 m (3,425 ft) may also make the well more prone to water production.
  • bottomhole pressure data is either obtained with the help of downhole gauges or with the help of calculated bottomhole pressures and used to control the rates of injection and thus pressures to achieve our tip strengthening goals.
  • main treatment the actual planned fracking treatment, termed as “main treatment” will be pumped with an intention to fracture stimulate the well.
  • the observations of rate and pressure made during the fracture tip strengthening process will influence the main treatment design.
  • injection pressure profile i.e., the slope of net pressure versus time in log-log plot to determine geometry — whether the fracture is extending or increasing in height or if it is a radial fracture.
  • Step 3 Analyze the bottomhole injection pressures in Step 3 to determine the primary geometry and perform a pressure fall-off test to determine if fracture height growth was observed, which should generally be the case if a lack of barrier is suspected.
  • the slurry (fluid + solids) laden fluid must be flushed into the formation with the same linear gel, but over-flushing must be avoided.
  • a freeze protect fluid may be pumped as the end of flush if the wells are in colder regions.
  • Pressure should be monitored closely during the injection period particularly when proppant is being in pumped. Where a Vs to % slope can be identified in a log-log plot of net pressure versus time, there is sufficient indication that the fracture is now bound. If the slope is near zero or trending in the negative direction, the injection rate is reduced until a positive slope is observed.
  • the pad may consist of low gel loading cross linked fluid such as 20 Ibm/Mgal borate cross linked fluid used in the simulation of example case and hence will be prone to generating net pressures. Use plots such as shown in FIG. 3A as guidelines to limit net pressures while constantly monitoring them.
  • the final fracture geometry may be similar to the illustration shown in the simulations results shown in FIG. 6.
  • the advantages of the new method may include one or more of the following in any combination(s) thereof:
  • Step Rate Test SRT
  • SRT Step Rate Test
  • Step Rate Test Procedure at epa.gov/sites/default/files/documents/INFO-

Landscapes

  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • General Physics & Mathematics (AREA)
  • Geophysics (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Adornments (AREA)
  • Micromachines (AREA)
  • Investigating Strength Of Materials By Application Of Mechanical Stress (AREA)

Abstract

L'Invention concerne un procédé de fracturation d'un réservoir dans lequel le traitement de stimulation de la fracture principale est précédé par le dépôt de solides non dissolvants dans des pointes de fracture dans lesquelles une croissance excessive vers le bas ou vers le haut n'est pas souhaitée, ce qui permet de commander la géométrie de la fracture. Le procédé augmente ainsi la production d'un fluide, tel que de l'eau, du pétrole ou du gaz, à partir dudit réservoir, et évite une propagation de la fracture hors de la zone productrice, vers des zones non souhaitées..
PCT/US2023/063236 2022-03-11 2023-02-24 Renforcement de pointes de fracture pour la fracturation de précision WO2023172823A2 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US202263318843P 2022-03-11 2022-03-11
US63/318,843 2022-03-11

Publications (2)

Publication Number Publication Date
WO2023172823A2 true WO2023172823A2 (fr) 2023-09-14
WO2023172823A3 WO2023172823A3 (fr) 2023-10-19

Family

ID=87935860

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2023/063236 WO2023172823A2 (fr) 2022-03-11 2023-02-24 Renforcement de pointes de fracture pour la fracturation de précision

Country Status (2)

Country Link
US (1) US20230313658A1 (fr)
WO (1) WO2023172823A2 (fr)

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN117266820B (zh) * 2023-11-21 2024-01-23 太原理工大学 一种基于液氮冷却储层的水压裂缝扩展方位控制方法

Family Cites Families (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5322126A (en) * 1993-04-16 1994-06-21 The Energex Company System and method for monitoring fracture growth during hydraulic fracture treatment
US6192985B1 (en) * 1998-12-19 2001-02-27 Schlumberger Technology Corporation Fluids and techniques for maximizing fracture fluid clean-up
US8082992B2 (en) * 2009-07-13 2011-12-27 Halliburton Energy Services, Inc. Methods of fluid-controlled geometry stimulation
US9394774B2 (en) * 2012-08-20 2016-07-19 Texas Tech University System Methods and devices for hydraulic fracturing design and optimization: a modification to zipper frac
US10788604B2 (en) * 2014-06-25 2020-09-29 Schlumberger Technology Corporation Fracturing and reactivated fracture volumes

Also Published As

Publication number Publication date
US20230313658A1 (en) 2023-10-05
WO2023172823A3 (fr) 2023-10-19

Similar Documents

Publication Publication Date Title
Smith et al. Hydraulic fracturing
CA2277528C (fr) Methode amelioree de recuperation du petrole
Soliman et al. Fracturing unconventional formations to enhance productivity
Vincent Proving It–A Review of 80 Published Field Studies Demonstrating the Importance of Increased Fracture Conductivity
US8074715B2 (en) Methods of setting particulate plugs in horizontal well bores using low-rate slurries
US20150345268A1 (en) Applications of ultra-low viscosity fluids to stimulate ultra-tight hydrocarbon-bearing formations
Abou-Sayed et al. Multiple hydraulic fracture stimulation in a deep horizontal tight gas well
US10087737B2 (en) Enhanced secondary recovery of oil and gas in tight hydrocarbon reservoirs
US20140096954A1 (en) Method of developing subsurface barriers
Soliman et al. Impact of fracturing and fracturing techniques on productivity of unconventional formations
US20230313658A1 (en) Strengthening fracture tips for precision fracturing
McDaniel et al. Limited-entry frac applications on long intervals of highly deviated or horizontal wells
Azevedo et al. Challenges faced to execute hydraulic fracturing in Brazilian pre-salt wells
Hudson et al. Hydraulic fracturing in horizontal wellbores
Snow et al. Field and laboratory experience in stimulating ekofisk area north sea chalk reservoirs
Norris et al. Hydraulic Fracturing for Reservoir Management: Production Enhancement, Scale Control and Asphaltine Prevention
CA2707209A1 (fr) Methodes de stimulation maximale aux chocs avec le volume minimal, vitesse minimale et croissance controlee des fractures
Gao et al. An Overview of Hydraulic Fracturing Stimulation Practices of a Joint Cooperation Shale Gas Project in Sichuan Basin
McDaniel A Review of Design Considerations for Fracture Stimulation of Highly Deviated Wellbores
Cikes et al. Formation damage prevention by using an oil-based fracturing fluid in partially depleted oil reservoirs of Western Siberia
Istayev et al. Hydraulic Fracturing in a Devonian Age Carbonate Reservoir: A Case Study
Sun et al. A Case Study of Hydraulic Fracturing in Ordos Shale Under the Combined Use of CO2 and Gelled Fluid
Bagci et al. An Integrated Geomechanical Modeling and Completion Selection for Production Enhancement from Lower Tertiary Wells in GOM
Nguyen et al. Design optimisation of hydraulic fracturing for Oligocene reservoir in offshore Vietnam
Dietzel et al. Stimulation of a low permeability natural fractured reservoir in the North-West German carboniferous

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 23767563

Country of ref document: EP

Kind code of ref document: A2